The following is a
summary of a technical workshop on the California Public
Utilities Commission's (CPUC) Draft Initial Study regarding
Southern California Edison Company's application to divest 12 of
its fossil-fueled power plants. This document is not an official
record of the event, which was not subject to the CPUC's
recording rules. Wherever possible, speakers are identified by
name. However, many participants did not identify themselves when
speaking, or they submitted anonymous questions in writing. Many
of the answers have been truncated and paraphrased, and
clarifications have been added in brackets.

Scott Steinwert of
Public Affairs Management (PAM) opened the workshop at 10:05 a.m.
He said the purpose of the workshop was to allow Edison to
respond, to propose modifications for and take comments and
questions about the Draft Initial Study (DIS) prepared by the
CPUC for Edisons divestiture application.

Bruce Kaneshiro of the
CPUC provided a brief explanation of the electric utility
restructuring effort, stating that the CPUC's goal is to begin
competitive retail sales of electric service on January 1, 1998.
A possible barrier to a competitive market is the exercise of
market power in the generation sector. As a way to remove this
barrier, the Commission proposed that Edison and Pacific Gas
& Electric Company (PG&E) voluntarily "divest"
or sell a portion of their in-state fossil-fueled power
generation capacity. As a result, Edison applied to divest nearly
100 percent of its in-state fossil-fueled capacity. [Edison will
continue to own a small fossil-fueled plant on Catalina Island.]
Kaneshiro emphasized that restructuring will occur with or
without divestiture.

Kaneshiro explained that
the Draft Initial Studies conducted for the two divestiture
applications are "decision point documents." The CPUC
will use these studies to determine whether to conduct a full
Environmental Impact Report (EIR), as defined in the California
Environmental Quality Act (CEQA), or issue a Negative Declaration
or a mitigated Negative Declaration. He stated that the ultimate
goal for CPUC staff, its consultants and subcontractors is to
prepare the "appropriate document."

Steinwert then directed
attention to a panel of speakers employed by Edison: Margaret
Cheng, a Manager in Edison's corporate financial planning and
analysis group; Bill Ostrander, Manager of Environmental
Services; Tom Burhenn, Manager of Regulatory Affairs; Robin
Walther, Manager of Regulatory Policy; and Jeff Koch, an attorney
in the law department.

Koch began by announcing
that the Ventura County Air Pollution Control District (APCD) now
agrees with Edison that divestiture of plants in the district
will not have a significant impact on air quality. Koch
introduced Dick Baldwin, an Air Pollution Control Officer with
the Ventura APCD, to confirm the agreement. Baldwin stated that
when the district first met with CPUC and Edison personnel, it
left with an inaccurate perception of the differences between
restructuring and divestiture. The APCD also was unfamiliar with
CPUC procedures. With a more thorough understanding of the issues
gained through further meetings with Edison, Baldwin said, the
district now agrees that divestiture alone will not have
significant impact on air quality.

Under state law, Baldwin
said, APCDs are prohibited from changing the terms of a permit
because of a change in ownership. The only responsibility the
district has is to update standards in the permits, he said,
which occurs once each year. Unlike the CPUC, the district has no
discretionary authority to approve or disapprove the sale. The
Ventura APCD currently processes five to 10 permits per month
because of changes of ownership, Baldwin said, and has never
added new permit requirements in any case.

However, if the new
owner of a plant wants to make physical changes, then a new
process begins, Baldwin said. During this process, called
"new source review," the applicants must propose
actions, such as obtaining emissions offsets credits, that would
more than offset any increased emissions; applicants must also
utilize best available control technology (BACT) to minimize
emissions. The district also intends to modify Rule 59, which
specifies emission standards for nitrogen oxides and other
compounds from utility boilers, to ensure the rule applies to the
new owners. The district is currently going through an advisory
process regarding Rule 59, Baldwin said, in preparation for
amending the rule.

Baldwin said the
district remains concerned with the potential impacts of
restructuring, and would have liked to have seen an environmental
analysis for that issue. However, he noted, the state Legislature
in Assembly Bill 1890 removed the CPUCs discretion in
conducting an environmental analysis regarding restructuring. He
emphasized again that the APCD's position is that changes of
ownership for the divested plants will not require changes in
permits.

Baldwin then answered
some clarifying questions from the audience.

Q: (an unknown audience
member) The new source review that you mentioned, what exactly is
that?
A: (Baldwin) It is a permitting process for any facility in
California that involves new construction, or adding to or
modifying existing equipment. Its a permit review process
to ensure that this new or modified equipment uses BACT, and, for
sources greater than 500 tons [of emissions] per year, that any
emissions are more than fully offset.
Q: (from Martha Sullivan of the CPUC) When do you expect that
[change to Rule 59] to be complete?
A: (Baldwin) July 15, 1997.
Q: (unknown audience member) Is Rule 59 exclusively an emission
rate rule?
A. (Baldwin) No, its based on net pounds of nitrogen oxides
per net megawatt-hour (MWh). It also includes total quantity, as
mandated by the permit.
Q: (unknown audience member) So that is the rate and not the
total quantity of emissions?
A: (Baldwin) Thats correct. The total quantity of emissions
would be that in the permit, which is basically the full
generating capacity of the plantabout 750 MW for Ormond
Beach and roughly 200 MW for Mandalay. Edison, or any other
owner, can operate up to the capacity of the facility under the
current permit.

Koch then provided an
explanation of Edisons internal process for filing the
divestiture application in November 1996. It began with a
thorough review of the potential environmental impacts related to
the sale. Edison concluded that the proposal in itself would not
have potential foreseeable environmental impacts, and that the
application probably is not even a "project" as
described in CEQA. Even if it was a "project," Koch
added, Edison determined that any CEQA review should conclude
that there is no potential impact, thereby allowing the CPUC to
issue a Negative Declaration.

According to Koch,
Edison was surprised that the CPUCs DIS not only identified
potential environmental impacts, but also, based on a preliminary
review of the document, seemed to identify very large
environmental impacts. Since consulting with the study team,
Edison understands the DIS is not meant to reflect an aggregate
picture of what could happen in the future, but rather is meant
as a preliminary assessment of the worst conceivable situation at
each plant. For example, with respect to the aggregate capacity
increases predicted in the study, Edison would contend those
increases are impossible, Koch said, and believes the CPUC staff
would agree such a scenario is unlikely.

Koch said his
understanding is that CPUC staff still believes there could be
substantial impact from Edisons proposal. We just cannot
agree with that conclusion, Koch said. We still see no potential
environmental impacts from the project, certainly none that are
reasonably foreseeable, and certainly none that are nearly as
large as those identified in the DIS. So, we are here today not
so much to offer possible mitigations measures, or to propose an
EIR process, rather we are here just to state why we disagree
with the conclusions in the DIS.

Koch continued, we think
the DIS makes two very fundamental CEQA-type errors and these are
the basis of our disagreement with the documents
conclusions. The first is the baselinethe picture of the
world without the project, the environmental conditions that
would exist if the proposal is not approved by the agency.
Its our belief that the draft study should be focused just
on divestiture, he said, rather than on the broader restructuring
that is also taking place.

The second error we
believe the study engages in, Koch said, is that the level of
speculation and unsupported assumptions is inconsistent with the
purposes of CEQA. [A CEQA review] is supposed to compare the
environmental conditions that would exist if the Commission
approves the project, with those that would exist if the project
is not approved. A CEQA review is a forward-looking process that
tries to make reasonable projections of what will happen in the
future with the project, versus without the project, he
continued. And none of us, neither the Commission nor anybody
else, can predict with certainty what the future will be.

An Initial Study is not
intended to be precise look at the future, Koch said, but it is
supposed to be a fact-based effort. Unsupported evidence is not
permissible under CEQA, even in a DIS, he said. To proceed to an
EIR, or requirements for mitigation, you need substantial
evidencefacts or reasonable assumptions based on
factsof potential significant environment impacts. Koch
asserted Edisons belief that a number of assumptions
critical to the studys conclusion are at best speculative
and unsupported by fact, while others are incorrect or are
contradictory to others.

Concerning the baseline
assessmentthe legal and regulatory conditions that we would
expect to be in place if the project is not approvedthe DIS
incorrectly concludes that Edison would retain all 12 plants, and
would be in position to exercise market power, Koch said. One way
to do that would be to reduce production, which may have market
impact, but interestingly enough, may reduce environmental
impacts. In reality, even if the divestiture application is not
approved, state law [AB 1890] mandates that all utility owned
fossil-fueled plants must be deregulated no later than the end of
2001, Koch said. For a variety of reasons, we can assume that
will happen sooner rather than later.

The plants will not be
removed from regulation by APCDs or other agencies with
environmental regulatory authority, Koch emphasized, but will be
removed from CPUC regulation. They will simply have to survive
like any other facility in any other industry. A slight wrinkle
exists with those plants identified as "must-run" for
reliability reasons, Koch said. These plants will not be able to
shut down unless other things occur. They wont be regulated
by CPUC, but rather by a set of contracts and the Independent
System Operator (ISO). This will be the case whether or not the
plants are divested. The fundamental point is that all of these
plants will be removed from CPUC regulatory authority, Koch said,
including CPUC authority over any future sale of those plants.

Koch asserted that the
most defensible assumption is that utilities, once restructuring
occurs, will divest all or a large portion of their plants
because mechanisms will exist that create strong incentives for
them to do so. But even if Edison retains all plants, there are a
variety of mechanisms in place that would prevent Edison from
exercising market power on the scale predicted in the study. The
most important is the Federal Energy Regulatory Commission
(FERC), This is not speculation about the future, Koch added.
FERC has made it very clear that it is watching the competitive
market in California, and that it will [enforce market power
rules].

Edison has filed an
application with FERC proposing bidding restrictions that would
be employed if the market opens up before we divest the plants,
Koch said. They havent been approved yet. However, in
comments filed regarding our proposal, many of the complaints do
not assert that Edison would use market power to reduce
production and raise prices, but rather express concern that
Edison would behave too competitively by underbidding its
wholesale power. We think thats a logical response by our
competitors, and we think FERC will approve our proposal, Koch
said. But the point is, FERC would prevent Edison from exercising
market power, and we believe that for the study to assume the
contrary is not defensible under CEQA.

The other main error the
study engages in is use of speculation, or assumptions that are
unsupported by the facts, Koch said. An example is in the
determination of whether or not the new owners would have the
incentive and the ability to generate more power than Edison at
all the plants. Here the authors assumed a fixed price and tried
to determine how the new owners would behave at that fixed price.
They determined that some generators could make money at that
price by increasing operations. However, they did not include a
feedback process, which examines how the increased generation
will affect price, Koch said. Failing to take this into account
leaves a very flawed result. Edisons concern is that the
study doesnt conclude that pricing cannot be addressed
because of insufficient information. Instead, it continues to
make other conclusions based on the fixed price scenario, leading
to further inaccuracies, Koch said.

In another example, Koch
said, the study concludes that because the new owners will
initially be able to participate in the Direct Access market,
while utilities cannot, the divested plants may be operated at
significantly greater levels than if the utility continued to own
the plants. A far more plausible assumption, Koch said, is that
the new plant owners will not fulfill supply obligations with
their own generation if the Power Exchange (PX) market price is
significantly below their price of generation. They would buy the
power on the open market. Customers do not care where they are
getting their power, Koch said, as long as they are getting
power; so we believe that the Direct Access market will be
dictated by PX market.

Another error occurred
because the study authors failed to use the same assumptions on
both sides of the equationon the non-divestiture side and
the divestiture side, Koch said. Its not discussed in depth
in the study, but through conversations with staff, Koch said he
understands that one of the authors claims is that there
are significant advantages to owning a portfolio of plants, as
opposed to owning a single plant. But Koch does not think
its fully explained in the study exactly what these
advantages entail, Koch said. While Edison believes there will be
advantages of shared ownership and shared management, they will
be modest advantages at best, Koch said. So if youre going
to make that assumption, you have to make it on the divestiture
side as well: that the new owners will recognize these advantages
and purchase more plants in a manner that suits them best.

Koch added that the
logical conclusion one would reach from the DIS is that after
restructuring and divestiture, the market would be much more
inefficient, because relatively high-cost, low-efficiency plants
actually increase generation. So, unless there is an explosion in
demand, these gas-fired plants are either replacing lower-cost
generation or running needlessly, burning fuel for no purpose,
Koch said. The reports perceived decrease in efficiency is
in direct contradiction with the CPUCs own conclusions that
restructuring will increase efficiency, he said.

Koch stated that
its more likely that operations will continue more or less
like they do todaytheres bound to be some changes
because of restructuringbut we dont expect anything
on the scale that the study predicts.

Basically, he continued,
the potential impacts identified in the DIS depend on three
things: increased generation, repowering and property transfer.
Edison believes the prediction of increased generation is:
speculative and implausible; subject to existing rules and
permits; and inconsistent with the DISs repower
assumptions. In addition, the prediction is carried through to
the air quality chapter, Koch said, where it translates into
predictions of very large increases in air emissions.

Regarding repowering,
Koch added, my understanding is that other portions of the study
assume that units that are shut down will be repowered; but that
will trigger a CEQA process and a new source review process at
the APCD. We think its implausible that the plants will be
repowered on the scale predicted in the study, Koch said. Even if
Edison were the owner, it would have the same incentives to
repower.

Concerning property
transfer, we do agree that because of our divestiture proposal,
and the way weve structured it, there can be impacts that
are not speculative, Koch said, such as building fences to
separate property. What we do disagree with is that any of these
are significant impacts under CEQA, he said.

The one area of
potential significance is that NOx rules are very specific to the
industry they apply to. On appearances, he said, the rules in the
Ventura and Mojave Districts seem to apply only to utility owned
facilities. Therefore, the plants would cease to be subject to
the NOx rule after divestiture, either because there is no rule,
or because the plants fall under a different rule. In Ventura,
however, the emission limits in the rule are stated in the
permits, which the new owners would inherit. In any case, the
districts, including Mojave and Ventura, are in the process right
now of changing the rules so they apply to all owners, Koch
concluded.

Koch then took several
oral questions from the audience.

Q: (Marc Joseph,
Coalition of Utility Employees) In your slide stating that the
end result is an expectation that divestiture will cause market
inefficiencies, was that statement based on the table in the DIS
that shows that all the plants would greatly increase generation,
or was there something else behind that?
A: (Koch) It was based on that table, but also on certain
economic discussion in Attachment C in the DIS.
Q: (Joseph) What are the inefficiencies youre talking
about?
A: (Koch) Basically what I was trying to identify was relatively
high cost generation somehow replacing lower cost generation or
just being wasted.
Q: (Joseph) From any of the plants, or all plants together?
A: (Koch) Well, certainly from all the plants together, but, in
addition, from any significant number of them. Now, its
certainly true that some of these plants may see increased
generation, while others would decrease, but we view that as a
result of restructuring, not divestiture, because the same would
happen under Edison ownership.

After a short break,
CPUC and Edison officials answered a few written questions. Koch
said Edison would provide written answers to other submitted
questions, and provide those answers with Edison's comments on
July 3, 1997.

Q: (Marc Joseph) Who at
the Commission will decide whether to prepare an EIR or a
Negative Declaration: the ALJ [Administrative Law Judge], the
Assigned Commissioners or the full Commission?
A: (Martha Sullivan, CPUC) The Energy Division will complete its
analysis and come to a recommendation in July. If the Assigned
Commissioners, President Conlon and Commissioner Bilas, are able
to reach a unanimous decision, then their decision will stand. If
they feel they need to take the decision before the full
commission, the first available meeting is August 1; the next one
is in the first week of September.

Q: (Bob Fisher,
consultant to the City of Long Beach) If the lot splits at plant
sites (e.g., Huntington Beach) are addressed by an EIR or
Negative Declaration in CPUC action, does this affect either the
Coastal Commission or local agency determination of need for a
Coastal Development Permit and/or for parcel maps? If the
resulting use pattern is inconsistent with zoning, is that an
item to be addressed in the EIR?
A: (Cynthia Burch, Outside Counsel for Edison) In our technical
resources document we did evaluate any zoning issues. Since there
are no changes in use patterns being proposed by divestiture
alone, there was no problem there. With respect to whether, if
there is an issue, it is to be addressed by this process, we
concluded: Yes, to the extent that the CEQA process is part of
any agency action thats needed to effectuate divestiture,
this process covers it. The CPUC is the lead agency. So your
comments would have to be provided in this process.
Q: (Fisher) Would an EIR provide more information on air quality
impacts near individual plant sites (e.g., Huntington Beach) and
more consideration of alternatives and potential mitigation
measures? If so, why and how? If not, why not?
A: (Koch) To some extent that question may be more for the
Commission as the lead agency. Its our position that the
pollutants that we are talking about here, the criteria
pollutants, do not really have local impacts; they have regional
or basin-wide impacts. Of course an EIR would address air quality
impacts in more detail than an Initial Study. But we believe
its clear, just from an adequate Initial Study, that there
are not air impacts necessitating an EIR. An EIR does consider
alternatives to the project put forth, but they are only
alternatives that would accomplish the same objective as the
project. In this case, our proposal is the sale and transfer of
ownership through an auction procedure. So an EIR would look at
other ways of accomplishing that.
Q: (Fisher) Does your proposal not also include the termination
of bundles?
A: (Koch) Yes.
Q: (Fisher) Is there new information on Edisons
transmission upgrade proposal and on the must-run designations of
the plants [local reliability bundles]? Does that require
additional environmental analysis or change existing analysis?
A. (Koch) There have been developments since the divestiture
application was filed in November. What we were hoping for at
that time was that the determination of must-run plants would be
made by now, and that we would receive some sort of rate-making
mechanisms for those upgrades. We were expecting that by about
this time, the must-run plants would be identified, and that it
would have been shown that the number of must-run plants could be
reduced through upgrades. The result of that is that as of today,
we have a larger number of must-run plants than we would have if
our transmission upgrades had taken place, and we dont know
exactly what those stations are. We expect that by this summer or
early fall, the number of must-run plants will be identified; and
expect it will be more than the two identified after the
transmission upgrades. In our initial application, we proposed to
sell off the plants in certain bundles. Now it looks like each
bundle would have a must-run plant. That complicates the sale
because no one will be interested in buying a must-run plant
until they have the regulatory certainty of an approved ISO
must-run contract. Until those contracts are more precisely
determined, we cant sell those must-run plants, so we are
unbundling the plants and we will sell the non-must-run plants
first, then the must-run plants after the contracts are
determined.
Q: (Fisher) The reason I addressed that question to staff and
consultants was that I wondered, Would that new information
[regarding bundling] have an effect on how the consultants, in
their assessment of operators perceptions about markets and
behavior and decisions about repowering, derive the air quality
conclusions?
A: (Koch) Edisons position is that divestiture itself does
not cause any significant impacts whether a plant is must-run or
not. For a must-run plant, there will be some floor of generation
level, but that would be true whether it's owned by Edison or
somebody else.
A: (Edison's Robin Walther) My understanding is that the study
coming out today will identify generation options, but it
wont necessarily identify the minimal set for generation
options that are required to be must-run. For example, if we have
two plants in the Ventura area that could both be must-run, but
only one is needed, this study may specify that both stations are
must-run options. But ultimately there will be a screening
analysis used to determine which of the two is most appropriate
for designation as must-run.
Q: (anonymous) RECLAIM [air emissions offset] credits are
allocated annually to facilities in the South Coast Air Quality
Management District. Will additional credits held by Edison be
assigned or transferred to the new owners of these SCAQMD plants?
A: (Koch) Edisons proposal is that all the RECLAIM Credits
allocations, including future year allocations, for each
generating station will be sold along with the station.
Q: (the study teams Richard McCann of M.Cubed) We
havent seen a specific plant-by-plant allocation of the
RECLAIM credits. Is Edison going to provide that?
A: (Koch) I believe its in our permits, but we can
certainly provide that. Its also in the Plant Description
section of our November application, showing in a bar graph the
future allocation for each plant.

Koch then said he would
answer one question submitted in writing by members of the study
team, and that Edison would later provide written answers to the
other questions in its written comments due July 3rd.

Q: (McCann) At what
point in time would the 12 plants be deregulated and
market-valued? What guarantee is Edison giving that this will
occur before the December 31, 2001, date stated in AB 1890 and
assumed in the Initial Study? Please provide any documentation
[showing] that Edison plans to market-value these plants without
divestiture before December 31, 2001, and that Edison is planning
to sell these or any other plants.
A: (Koch) Edison is in no position to guarantee exactly when
these plants will be market-valued and deregulated; thats
up to the Commission more than Edison. The documentation that we
plan to sell and market-value these plants as soon as possible is
the application that is before the commission now. Its a
fair statement that weve been pressing for a determination
of that application as soon as possible. We cant say when
the plants will be market-valued without that process because we
have devoted all our efforts to proceeding with that application.
Q: (McCann) Whats happening with market-valuing the Mohave
and Four Corners generating stations [the out-of-state coal-fired
plants partially or wholly owned by Edison]?
A: (Koch) All of our fossil-fueled plants must be market-valued
before 2001. Most of our resources have been devoted to this
application, to market-valuing the gas-fired plants.
Market-valuing the coal plants will come later. We can only
guarantee that they will be valued by 12/31/01.

Q: (the study
teams Bob Logan) You state that after restructuring,
certain mechanisms will exist that will create a strong incentive
to divest. Please explain how these mechanisms will work. Please
provide citations [in your comments due to the CPUC on July 3]
supporting this position so we might include them in the study.
A: (Walther) One of the incentives that has been discussed is
that in a competitive environment, the power plant would want to
be able to have market-based pricing, and FERC would determine if
each facility is eligible for market-based pricing. The
assumption is that FERC would not approve market-based pricing
[if Edison owned enough plants to exert market power]. So there
is a strong incentive for us to divest the plants, even after the
market-valuation process, in order to get market-based pricing.

Scott Steinwert then
closed the workshop at 11:45 a.m., urging parties to submit
formal comments in the proceeding to the CPUC by 5 p.m. on July
3rd.